As current low sulfur content natural gas fields are being depleted, sour gas fields are increasingly developed to meet production demands. Acid gas removal from these fields (and especially removal of highly sour gas fields) requires significant capital investment as well as operating costs. Compounding such disadvantages, sour gas field production plants must also comply with gas pipeline specifications, energy efficiency and emissions requirements that have become increasingly stringent. Moreover, the acid gas content of at least some of these gas fields will increase over time and so places additional burdens on operating conditions and costs.
While numerous acid gas removal methods are known in the art, most of them have at least some drawbacks. For example, where a conventional amine absorption process is used, the circulation rate for the amine solvent (or other chemical solvent) is generally proportional to the acid gas content. Also, where the acid gas concentration is relatively high or increases over time, the steam demand for solvent regeneration is relatively high or increases, and with that imposes undesirably high greenhouse gas emissions. Still further, chemical solvents also exhibit saturation with respect to acid gas loading (i.e., mole of acid gas per mole of amine), which is especially disadvantageous at high or increasing acid gas concentrations.
On the other hand, where physical solvents are used, acid gas loading of the solvent actually increases with the acid gas concentration/partial pressure. Thus, at least in theory, physical solvents appear to be a desirable choice for acid gas fields with relatively high sour gas content. Furthermore, physical solvent regeneration can be accomplished to at least some extent by flash regeneration. Unfortunately, without external heating physical solvents can only be partially regenerated. Consequently, unless an external heat source (e.g., steam) is used for regeneration, physical solvents are currently deemed not suitable for deep treatment of sour gases, and particularly H2S, to meet pipeline gas quality (e.g., 2 to 4 ppmv H2S). Alternatively, heat recovered from the feed gas and/or a compressor discharge can be used to improve solvent regeneration as described in PCT/US09/58955. Such configurations and methods advantageously reduce energy and equipment requirements; however, they fail to produce a CO2 product with purity suitable for EOR and/or a sales gas product meeting pipeline specifications.
Additionally, due to the high solubility of hydrocarbons in physical solvents, the CO2 stream often contains more than 5 mol % of hydrocarbons, which fails to meet the CO2 purity required for enhanced oil recovery. For example, CO2 can be removed from a feed gas at supercritical pressure as described in U.S. Pat. No. 7,192,468. While such removal is relatively efficient, hydrocarbon losses are often undesirably high. Moreover, to some extent, recovery of hydrocarbons can be achieved by recycling of the low pressure flash gases; however, it is impractical due to the extremely high re-compression. Similarly, as described in PCT/US10/24382, acid gas is removed from a feed gas at pressures at or below those of the above '468 patent. However, the recovered CO2 stream still contains a relatively high amount of hydrocarbons, reducing product revenue and potentially rendering the CO2 unfit for EOR. Therefore, while physical solvent processes can be used for treatment of feed gases having significant amount of hydrocarbons, such processes often fail to recover hydrocarbon content in the CO2 stream as well as the treated gas stream, resulting in losses in product revenues and production of non-compliant products.
Thus, although various configurations and methods are known to remove acid gases from a feed gas, all or almost all of them suffer from one or more disadvantages. Among other things, physical solvent processes typically fails to produce a treated gas that meets below 4 ppmv gas pipeline specifications, and/or hydrocarbon concentrations are undesirably high in the removed CO2. Therefore, there is still a need to provide improved methods and configurations for acid gas removal.